Methods for treating a wellbore

ABSTRACT

A method of converting a completed well into a dual completed well that includes selectively pumping a water-based fluid into a first production zone of the completed well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the first production zone of the completed well, wherein the water-based gel has a pH of greater than about 5; disposing a layer of cement into the completed well above the water- based gel; perforating a second production zone of the completed well in a location above the layer of cement; drilling through the layer of cement; and breaking the water-based gel located in the first production zone of the completed well, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about 5 is disclosed.

BACKGROUND OF INVENTION

1. Field of the Invention

Embodiments disclosed herein relate generally to improved methods for treating a wellbore.

2. Background Art

Hydrocarbons (e.g., oil and natural gas) are typically produced by drilling and casing a single, main wellbore downward from the surface into a lower, primary production subterranean geologic formation (i.e., a “reservoir”) or zone within the formation. In order for hydrocarbons to be “produced,” that is, travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flow path from the formation into the wellbore. One key parameter that influences the rate of production is the permeability of the formation along the flow path by which the hydrocarbon travels to reach the wellbore. Sometimes, the formation rock has a naturally low permeability; other times, the permeability is reduced, for example, during drilling of the wellbore.

When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces; transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface; controlling formation fluid pressure to prevent blowouts; maintaining well stability; suspending solids in the well; minimizing fluid loss into and stabilizing the formation through which the well is being drilled; fracturing the formation in the vicinity of the well; displacing the fluid within the well with another fluid; cleaning the well; testing the well; transmitting hydraulic horsepower to the drill bit; fluid used for implacing a packer; abandoning the well or preparing the well for abandonment; and otherwise treating the well or the formation.

Drilling fluids or “muds” are typically classified according to their base material, i.e., the drilling mud may be either a water-based mud having solid particles suspended therein or an oil-based mud with water or brine emulsified in the oil to form a discontinuous phase and solid particles suspended in the oil continuous phase. In addition to a base fluid, drilling fluids typically further include weighting agents (most frequently barium sulfate or barite is used), bentonite clay to help remove cuttings from the well and to form a filter cake on the walls of the hole, thinners (e.g., lignosulfonates, polyphosphates and tinnins) to reduce flow resistance and gel development, and various additives that serve specific functions, such as polymers, corrosion inhibitors, emulsifiers, and lubricants. The effectiveness of a drilling fluid, and also of the additives found in the drilling fluid, is typically evaluated by measuring the rheological properties of the fluid.

During drilling, the mud is pumped downhole through a bore of the drillstring to the drill bit where it exits through various nozzles and ports. After exiting through the nozzles, the “spent” fluid returns to the surface through an annulus formed between the drillstring and the drilled wellbore. At the surface, the mud can be separated from the drill cuttings for reuse, and the drill cuttings can be disposed of in an environmentally accepted manner.

As stated above, wellbore fluids are circulated downhole to remove rock as well as deliver agents to combat the variety of issues described above. For a wellbore fluid to perform all of its functions and allow wellbore operations to continue, the fluid must stay in the borehole. Frequently, undesirable formation conditions are encountered in which substantial amounts or, in some cases, practically all of the wellbore fluid may be lost to the formation. For example, wellbore fluid can leave the borehole through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole. Thus, fluid loss or lost circulation is a recurring drilling problem, characterized by loss of wellbore fluids into downhole formations that are fractured, highly permeable, porous, cavernous, or vugular.

Induced fluid losses may also occur when the fluid weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations. A particularly challenging situation arises in depleted reservoirs, in which the drop in pore pressure weakens hydrocarbon-bearing rocks, but neighboring or inter-bedded low permeability rocks, such as shales, maintain their pore pressure. This can make the drilling of certain depleted zones impossible because the fluid weight required to support the shale exceeds the fracture resistance of the sands and silts.

One way of reducing or preventing fluid loss is by forming a filter cake on the surface of the subterranean formation. Filter cakes are formed when particles suspended in a drilling fluid coat and plug the pores in the subterranean formation such that the filter cake prevents or reduces both the loss of fluids into the formation and the influx of fluids present in the formation. A number of ways of forming filter cakes are known in the art, including the use of bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates. Fluid loss pills may also be used where a viscous pill comprising a polymer may be used to reduce the rate of loss of a wellbore fluid to the formation through its viscosity.

During completion operations, when fluid loss is suspected, a fluid loss pill of polymers may be “spotted” into the wellbore to reduce or prevent such fluid loss by injection of other completion fluids behind the fluid loss pill to a position within the wellbore which is immediately above a portion of the formation where fluid loss is suspected. Injection of fluids into the wellbore is then stopped, and fluid loss will then move the pill toward the fluid loss location. Additionally, upon completion of drilling, the filter cake and/or fluid loss pill may stabilize the wellbore during subsequent completion operations, which typically include casing and cementing the well as well as installing any necessary production equipment.

Following installation of the production equipment, fluids can be produced from the various subsurface formations. Fluids may be recovered either through a single production zone or a plurality of production zones. There are several known methods for producing from a plurality of production zones, the simplest involving simultaneous production from all zones. Typically, production tubing is installed in a well that has been cased and cemented such that the production tubing and casing are perforated in the regions of the producing zones to allow hydrocarbons from each zone to simultaneously flow into the production tubing. However, due to the potentially differing flow rates and pressures in the different zones, cross-flow may occur, resulting in no production from one of the zones. The term “cross-flow” is used herein to refer to the situation where fluids from one zone (e.g., a high pressure zone) flow into a different zone (e.g., a low pressure zone) rather than into production tubing and out of the well. Due to the low productivity which may result from such cross-flow, it is usually impractical from a commercial standpoint to merely perforate the production tubing and casing adjacent these formations and commingle the production from the plurality of production zones. Similarly, in a horizontal well that extends through a single zone, perforations near the “heel” of the well (i.e., nearer the surface) may begin to produce water before those perforations near the “toe” of the well. The production of water near the heel reduces the overall production from the well.

Additionally, the quality of fluids produced from the different production zones may vary. That is, the quality of fluid produced from one zone may be greatly superior to that of another production zone, thus making it desirable to prevent the produced fluids from commingling. Also problematic is that, depending on the location of the well, there may exist regulations that forbid such commingling of fluids from separate production zones. One known method for preventing the commingling of fluids produced from a plurality of production zones involves drilling one or more “laterals” or “drain-holes” substantially horizontally outward into the production zones from the wellbore. As understood in the art, these laterals significantly increase the drainage area around the wellbore and provide an unrestricted flowpath for fluids from the outer regions of the formation directly into the wellbore.

Although there exist several prior art methods for treating a wellbore (e.g., completing multiple zones in a wellbore, maintaining well stability, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, etc.) there still exists a need for methods of treating a wellbore that will improve the overall economics of the drilling and production process.

SUMMARY OF INVENTION

In one aspect, embodiments disclosed herein relate to a method of converting a completed well into a dual completed well that includes selectively pumping a water-based fluid into a first production zone of the completed well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the first production zone of the completed well, wherein the water-based gel has a pH of greater than about 5; disposing a layer of cement into the completed well above the water-based gel; perforating a second production zone of the completed well in a location above the layer of cement; drilling through the layer of cement; and breaking the water-based gel located in the first production zone of the completed well, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about 5.

In another aspect, embodiments disclosed herein relate to a method of treating a well that includes selectively pumping a water-based fluid into a production zone of the well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the production zone of the well, wherein the water-based gel has a pH of greater than about 5; and breaking the water-based gel, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about 5.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a wellbore treated in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate generally to methods of selectively pumping a water-based fluid (prepared at the surface) into a production zone of a wellbore, allowing the fluid to form a continuous, non-flowing water-based gel that has properties capable of performing a variety of functions within the production zone of the wellbore, and subsequently breaking the water-based gel using a breaker fluid.

In accordance with the present disclosure, a water-based fluid may be selectively pumped into a wellbore. Selective pumping of the water-based fluid may be accomplished by “spotting” the water-based fluid into a zone or zones of interest, for example, one or more production zones. Additionally, a water-based fluid of the present disclosure should be pumpable, gellable, and breakable once gelled. That is, the water-based fluid should be pumpable initially and, over time, be capable of forming a breakable gel. The term “pumpable” is used herein to mean that the water-based fluid is in a flowing condition such that it may be easily pumped (i.e., it requires the minimum amount of pressure to force it through restrictions in the circulating fluid system, such as bit nozzles or down-hole tools) into the selected zone(s) of the wellbore, and, after placement, fully conform to the shape of the selected zone(s). The term “gellable” is used herein to mean that the water-based fluid is capable of forming a water-based gel once selectively pumped into the wellbore. The term “breakable” is used herein to mean that the water-based gel, once formed, is capable of being converted back into a water-based fluid that can be pumped out of the formation. Water-based fluids that may be used in embodiments of the present disclosure may include, for example, those described in U.S. Pat. No. 7,098,172 and U.S. Patent Application Ser. No. 60/946,882, which are both assigned to the assignees of the present disclosure. One of ordinary skill in the art will recognize that these are only listed as examples and are not intended to be limiting to the present disclosure.

Additionally, when pumped, the water-based fluid should have sufficient viscosity and/or plugging efficiency to at least substantially reduce fluid leakoff into the formation during or subsequent to its placement. Because a water-based fluid of the present disclosure is preferably pumped into a production zone of the wellbore, the water-based fluid should be non-damaging to the production zone and thus, in preferred embodiments, should have a pH greater than about 5, and more preferably greater than about 7. Additionally, the water-based fluid should be relatively non-toxic and safe to handle.

In a preferred embodiment, the pumpable water-based drilling fluid may be pumped into a wellbore at a rate below that capable of fracturing the formation. Furthermore, once selectively placed in the production zone(s) of the wellbore, the water-based fluid may be allowed to settle and form a continuous, non-flowing water-based gel that functions as a solid gel plug within the wellbore. The time required to let the liquid settle and form a water-based gel may vary, depending on the components used to form the gel.

The water-based drilling fluid may be selectively pumped into a cased well which may or may not have production zone(s) that are substantially depleted. Additionally, the water-based fluid may be selectively pumped into a well during drilling, i.e., into a well that has not yet been completed, in order to preserve completion of a well as well as to convert a single completed well into a dual- or multi-completed well (i.e., a well having more than one production zone).

As mentioned above, once the water-based fluid is selectively pumped into a production zone, the water-based fluid may harden to form a continuous, non-flowing water-based gel which may be used to plug a production zone of a formation in order to reduce or prevent fluid loss in the production zone during workover of a wellbore. Specifically, the continuous, non-flowing water-based gel may be used to preserve the formation during the conversion of a single completed well into a dual- or multi-completed well, as is discussed below.

According to preferred embodiments of the present disclosure, the water-based gel should not significantly penetrate the formation matrix beyond a distance on the order of about 1 cm from the rock-face in order to reduce or prevent damage to the formation and allow for subsequent recovery or injection of fluids into the formation. Additionally, the water-based gel, similar to the water-based fluid, should have a pH of greater than about 5, and more preferably, greater than about 7. This is desirable as it may reduce or prevent damage to the formation. The amount of water-based gel used in the presently disclosed process may be dependent on the geological properties of the formation as well as the existing perforations in the well.

In addition, as discussed above, the water-based gel should be breakable, i.e., reversible without the necessity of a strong acid. Conventional gels are typically broken by exposure to a strong acid. However, preferred embodiments of the present disclosure require that the water-based gel be breakable using a breaker fluid having a pH greater than about 5, and more preferably greater than about 7. Specifically, it is desirable to use a relatively basic (i.e., pH greater than about 5) breaker fluid so as to reduce or prevent formation damage that typically results when strong acids are injected into a formation, as well as to minimize corrosion of downhole equipment. Examples of sufficient breakers of the present disclosure include oxidative breakers, such as peroxides (e.g., sodium peroxide) and hypochlorite salts (e.g., lithium hypochlorite or sodium hypochlorite).

Upon exposure to a breaker fluid, the water-based gel may be converted back into a water-based “spent” fluid. This spent fluid preferably has a pH greater than about 5, and more preferably greater than about 7, similar as to when it was initially pumped into the wellbore, as discussed above, so as to reduce or prevent damage to the formation and/or damage to the drilling equipment. The breaker fluid may be incorporated into the initial fluid composition at the surface (as an internal breaker) to slowly break the gel over time, as, for example, through use of a chemically or thermally delayed oxidative breaker; or the breaker may be placed (e.g., selectively pumped) into the wellbore separately to reverse the gel on contact at the desired time. Once the gel has been converted back into a pumpable, spent fluid, it may be removed from the wellbore and/or used for any of the previously discussed functions for which fluids are typically used (e.g., to stabilize the formation).

As shown in FIG. 1, embodiments of the present disclosure include a method for converting a single, completed wellbore into a dual-completed wellbore. Such methods include selectively pumping a gellable, pumpable water-based fluid into a first production zone 12 of a completed well 10, allowing the water-based fluid to solidify and form a continuous, breakable, non-flowing water-based gel in the first production zone 12 of the completed well 10, disposing a layer of cement 14 above the water-based gel, perforating a second production zone 16 located above the layer of cement 14, drilling a hole through the layer of cement 14 in order to gain access to the formed gel located in the first production zone 12, and then breaking the water-based gel located in the first production zone 12 of the completed well 10 wherein the breaking comprises injecting a breaker fluid substantially through the water-based gel. As discussed above, both the water-based fluid and the water-based gel preferably have a pH greater than about 5, and more preferably greater than 7.

For the embodiment shown in FIG. 1, the water-based gel, once formed, should possess sufficient strength and rigidity so as to both support the layer of cement disposed thereon as well as to provide an impermeable barrier to the flow of fluids from the first production zone. In a preferred embodiment, the layer of cement may have a thickness of at least about 4 meters. Additionally, the water-based gel should be able to withstand environmental well conditions, for example, increased temperatures that may be present downhole.

Conventional breakers known in the art for breaking gels are typically comprised of at least a strong acid, which also typically results in a highly acidic spent fluid, and thus may be capable of breaking the layer of cement and/or damaging the formation and drilling equipment. In preferred embodiments of the present disclosure, the breaker fluid has a pH greater than about 5, and more preferably greater than about 7. This may reduce or prevent the breaker fluid from breaking (or otherwise impacting) the layer of cement disposed between the first and second production zones of the wellbore as well as reducing or preventing damage to the formation and/or any drilling equipment. Similarly, it is preferred that the “spent” fluid (the fluid that results from breaking the gel) have a pH greater than about 5, and more preferably greater than about 7.

After breaking the water-based gel, production tubing may be installed to facilitate production from both the first and second production zones, either simultaneously or in such a manner so as to prevent the produced fluids from commingling. It may be desirable to prevent such fluids from commingling for a variety of reasons, as discussed previously. In preferred embodiments, production tubing may be installed in the first production zone by drilling through the layer of cement after first perforating and installing production tubing in the second production zone.

In other preferred embodiments, the water-based gel may be used to preserve completion of the well while drilling through a production zone in a well that may or may not be cased. Specifically, a method of using the water-based gel to preserve completion may include drilling through a production zone of a wellbore, ceasing drilling in order to selectively pump a water-based fluid into the production zone, allowing the water-based fluid to form a continuous, non-flowing water-based gel in the production zone, resuming drilling of the production zone, and breaking the water-based gel upon completion of drilling, wherein the breaking comprises exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH greater than about 5, and more preferably greater than about 7. It is also preferred that the water-based fluid and water-based gel formed therefrom have a pH greater than about 5, and more preferably greater than about 7. The method may further comprise casing and cementing (“completing”) the well after breaking the water-based gel. Alternatively, the well may be completed prior to selectively pumping the water-based fluid into the production zone.

Embodiments of the present disclosure may provide for reduction or prevention of fluid loss and/or lost circulation when drilling according to conventional methods. This may occur prior to fluid loss and/or after fluid loss is detected. Additionally, embodiments of the present disclosure may allow for production from and zonal isolation within a dual- or multi-completed well such that fluids produced from each production zone are prevented from commingling.

Advantageously, embodiments of the present disclosure may have utility over a broad range of operating conditions. Specifically, the water-based fluid and the water-based gel should be effective in the presence of high salt concentration brines as well as be resistant to thermal degradation at temperatures generally encountered during drilling operations. Furthermore, the water-based gel should be formulated over a broad range of onset times and strengths while remaining relatively insensitive to minor variations in conditions under which it is formulated. Thus, the water-based gel should be readily suited for on-site preparation in the field where process controls are often imprecise, such as remote hostile onshore and offshore locations.

Additionally, embodiments of the present disclosure may offer practical advantages over conventional techniques for treating a wellbore. The methods disclosed herein are cost effective in that the components used to form the water-based fluid, and thus the gel, may be readily available and inexpensive while still being relatively non-toxic to the environment and safe to handle.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims. 

1. A method of converting a completed well into a dual completed well, comprising: selectively pumping a water-based fluid into a first production zone of the completed well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the first production zone of the completed well, wherein the water-based gel has a pH of greater than about 5; disposing a layer of cement into the completed well above the water-based gel; perforating a second production zone of the completed well in a location above the layer of cement; drilling through the layer of cement; and breaking the water-based gel located in the first production zone of the completed well, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about
 5. 2. The method of claim 1, further comprising: installing production tubing after breaking the water-based gel.
 3. The method of claim 1, further comprising: producing from both the first production zone and the second production zone of the completed well.
 4. The method of claim 3, further comprising: preventing commingling of production from the first and second production zones.
 5. The method of claim 1, wherein the first production zone is depleted.
 6. A method of treating a well, comprising: selectively pumping a water-based fluid into a production zone of the well, wherein the water-based fluid has a pH of greater than about 5; allowing the water-based fluid to form a continuous, non-flowing water-based gel in the production zone of the well, wherein the water-based gel has a pH of greater than about 5; and breaking the water-based gel, wherein the breaking comprises: exposing the water-based gel to a breaker fluid, wherein the breaker fluid has a pH of greater than about
 5. 7. The method of claim 6, further comprising: drilling through the water-based gel prior to breaking the water-based gel.
 8. The method of claim 6, further comprising: completing the well after breaking the water-based gel.
 9. The method of claim 6, further comprising: producing from the well after breaking the water-based gel.
 10. The method of claim 6, further comprising: completing the well prior to selectively pumping the water-based fluid into the production zone of the well.
 11. The method of claim 10, wherein the water-based gel is used to preserve completion of the well. 